Modern oil and gas technologies commonly operate under severe conditions during the course of oil recovery and production. For instance, high pumping speed, high pressure in the pipelines, extended length of pipelines, and low temperature of the oil and gas flowing through the pipelines. These conditions are particularly favorable for the formation of gas hydrates, which can be significantly hazardous for oil productions offshore or for locations with cold climates.
Gas hydrates are ice-like solids that are formed from small nonpolar molecules and water at lower temperatures and at increased pressures. Under these conditions, the water molecules can form cage-like structures around these small nonpolar molecules (typically dissolved gases such as carbon dioxide, hydrogen sulfide, methane, ethane, propane, butane and iso-butane), creating a type of host-guest interaction also known as a clathrate or clathrate hydrate. The specific architecture of this cage structure can be one of several types (called type 1, type 2, type H), depending on the identity of the guest molecules. However once formed, these crystalline cage structures tend to settle out from the solution and accumulate into large solid masses that can travel by oil and gas transporting pipelines, and potentially block or damage the pipelines and or related equipment. The damage resulting from a blockage can be very costly from an equipment repair standpoint, as well as from the loss of production, and finally the resultant environmental impact.
The petroleum industry gives particular attention to clathrate hydrates because the conditions are often favorable for the formation of hydrates and subsequent blockages. There are many instances where hydrate blockages have halted the production of gas, condensate, and oil. Obviously, the monetary consequences for each of these instances are amplified when considering the volumes of production in deepwater applications where tens of thousands of barrels of oil are routinely produced daily and the shut-ins can take months to remedy. Additionally, restarting a shutdown facility, particularly in deep water production or transportation facility, is extremely difficult because of the significant amounts of time, energy, and materials, as well as the various engineering implementations that are often required to remove a hydrate blockage under safe conditions.
The industry uses a number of methods to prevent blockages such as thermodynamic hydrate inhibitors (THI), anti-agglomerates (AA), and kinetic hydrate inhibitors (KHI). The amount of chemical needed to prevent blockages varies widely depending upon the type of inhibitor that is employed. Thermodynamic hydrate inhibitors are typically used at very high concentrations (glycol is often used in amounts as high as 100% of the weight of the produced water), while KHI's and AA's are used at much lower concentrations (0.3-0.5% active concentration) and are typically termed low dose hydrate inhibitors (LDHIs).
Commonly it is accepted that KHI's interfere with the growth of the clathrate hydrate crystal, thus preventing the formation of the hydrates.
While AA's allow the crystal to form and then disperse the small crystal, KHI's prevent the formation of hydrate crystals by disrupting the crystal growth. It is commonly accepted that AA's act as dispersants of the hydrate crystals into the hydrocarbon phase, and therefore have a limitation that the liquid hydrocarbon phase must be present. Typically the liquid hydrocarbon to water ratio should be no greater then one to one to ensure that there is enough hydrocarbon to contain the dispersed hydrate crystals. Unfortunately, this limitation reduces the opportunity in the oilfield as many wells increase the amount of water produced very rapidly after the water breakthrough is observed.
There are several important factors to consider when evaluating the capabilities and performance of a hydrate inhibitor, but the most significant and directly relevant of these are the two factors subcooling and the hold time. Subcooling refers to the degree to which the temperature of the system can be lowered below the theoretical hydrate formation temperature at a given pressure, and is often referred to in terms of a ΔT value. The hold time refers to the amount of time that this sub-cooled system can be kept hydrate-free in the presence of a particular KHI. Thus a good KHI should have a large ΔT subcooling temperature, and be capable of long hold times at that temperature.